A wide variety of regenerable solvents are used to absorb H2S from hydrocarbon, hydrogen (H2), syngas, flue gas, waste gas, and other gaseous and liquid streams. Often, such streams also contain carbon dioxide (CO2), and at least some CO2 is typically absorbed along with the H2S, either inadvertently or intentionally. Other miscellaneous contaminants which may be absorbed include mercaptans, disulfides, hydrogen cyanide (HCN), ammonia (NH3), and various organic compounds, particularly, heavy hydrocarbons including aromatics.
H2S solvent absorption mechanisms can generally be classified as chemical absorption mechanisms which involve chemical reactions, physical absorption mechanisms based on favorable solubility, or combinations of the two. Common examples of chemical solvents are aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA). Alkanolamines are bases which react with H2S and CO2 to form weakly bound soluble salts which become unstable at elevated temperatures, thus reverting to the original gas which can then be stripped from solution by a carrier vapor, usually steam generated by reboiling the regenerator bottoms.
Examples of physical solvents include N-methyl-2-pyrrolidone (NMP) as used in the Lurgi GmbH Purisol process, propylene glycol as used in the Fluor Solvent process, homologues of the dimethylether of polyethylene glycol as used in the UOP Selexol process, refrigerated methanol as used in the Lurgi Rectisol process and morpholine derivatives as used in the Krupp Uhde Morphysorb process which have particular affinity for aromatics as well as H2S.
Examples of combined solvents include the various Shell Sulfinol solvents which combine the physical solvent sulfolane with a chemical solvent such as diisopropanolamine (DIPA) or MDEA.
Absorbers, or contactors, are used to contact the gas or liquid stream to be treated with such solvents to remove H2S and CO2. The solvent leaving the absorber is rich in H2S, and therefore, is generally referred to as a “rich” or “fat” solvent while the solvent fed to the absorber is referred to as “lean” solvent. A rich solvent can be regenerated by various means using heat, pressure reduction, partial-pressure reduction, or combinations thereof to strip the H2S, CO2, and volatile contaminants using a stripping or carrier vapor, which is usually steam and/or solvent vapor, in order to produce a lean solvent that can be recycled back to the absorbers for further H2S and/or CO2 removal. The H2S and CO2 that have been removed from the rich solvent by the regeneration process are collectively referred to as “acid gas” following condensation of the associated carrier vapor and subsequent separation.
Elemental sulfur is often recovered from the acid gas using processes such as the modified Claus sulfur recovery process. The modified Claus process typically begins with partial combustion of the acid gas with an oxygen (O2) source in a reaction furnace, or thermal reactor. The O2 source can be air, O2-enriched air or essentially pure O2. Of course, ambient air is typically the most convenient and economical source of O2 for such a reaction furnace. The amount of O2 fed to the reaction furnace is controlled to oxidize nominally one third of the H2S to sulfur dioxide (SO2) according to Equation 1:H2S+1.5O2→SO2+H2O+ΔH  (1)
The SO2 generated by Equation 1 then reacts with the remaining two-thirds of the H2S to form sulfur and water vapor according to the Claus reaction as shown in Equation 2:2H2S+SO2→3S+2H2O+/ΔH  (2)
Most CO2 in the acid gas fed to the reaction furnace is basically inert, and passes through the reaction furnace unchanged. Most other contaminants present in the stream are ideally combusted to generally inert products. However, for so-called “lean” acid gas feeds containing relatively low concentrations of H2S and correspondingly high concentrations of CO2, problems can arise in that the inert CO2 acts as a diluent, reducing the flame temperature in the reaction furnace. This can make it difficult to control the desired reactions. Where ambient air is used as the source of O2, feed gas concentrations of less than 40 vol % H2S can result in insufficient flame temperatures for proper combustion. In particular, the low flame temperatures resulting from combustion of a lean acid gas feed may not be adequate for complete destruction of contaminants. For example, such contaminants can include organic materials such as hydrogen cyanide (HCN), mercaptans, disulfides, or hydrocarbons. Particularly problematic are aromatics such as benzene, toluene, ethylbenzene and xylenes, collectively known as BTEX, which are likely to be incompletely destroyed at flame temperatures below 2000-2200° F. Incomplete destruction can result in contamination of the sulfur product or fouling of downstream equipment or catalyst. Certain studies indicate that even 10-20 ppm of BTEX can result in severe catalyst deactivation within a short period of time. Residual BTEX levels of less than 1 ppm are desirable to reasonably ensure negligible adverse impact, while higher residual levels of simpler hydrocarbons less prone, for example, to downstream polymerization are tolerable.
In some cases, lean acid gas feeds may be accommodated by the use of a two-zone reaction furnace where 35-50% of the total H2S in the acid gas feed is combusted in a first, or primary, reaction zone for increased flame temperatures, with the remaining H2S fed to a second reaction zone in which there is negligible residual O2. Since 1600-1800° F. is generally considered a safe minimum for flame stability, splitting the acid gas feed can be a simple means of achieving stable combustion with H2S concentrations as low as 25 vol %. However, this becomes impractical in the presence of many contaminants, as those contaminants bypassed to the second zone will not be adequately destroyed at the lower temperature.
Other methods of handling lean acid gas feeds include preheating the acid gas feed and/or the combustion air. For example, high-pressure steam, heat transfer fluid, fired heaters, molten salt baths or electric resistance can be used to heat the acid gas feed, the combustion air, or both. However, the increase in flame temperature is generally limited to 300-400° F. using such methods.
Another method of handling lean acid gas feeds is O2 enrichment of the combustion air up to the use of relatively pure O2. The use of O2-enriched air can be an effective means of increasing temperature while also reducing equipment size. However, the operating cost can be high and such methods tend to be poorly suited to remote locations or hot climates.
Still another method of handling a lean acid gas feed is the selective absorption of H2S over CO2 in cases where CO2 removal is not required. Selective absorption typically takes advantage of higher H2S chemical reaction, and hence absorption, rates (as opposed to equilibria) by the use of specialty solvents combined with limited mass transfer surface and contact time in order to selectively absorb H2S while allowing the CO2 to “slip”. However, optimization of mass transfer elements is often difficult to predict and tends to vary with rate. The amount of CO2 that can be slipped without also slipping H2S can also be limited, and potential undesirable organics may still be absorbed. Still further, such methods are not effective where it is desirable to remove both H2S and CO2 from the stream to be treated.
Acid gas enrichment is yet another option. While many such schemes exist, most involve low-pressure selective re-absorption of the H2S from the initial acid gas stream followed by a second solvent regeneration step to yield a second acid gas stream of higher H2S concentration. Such processes invariably require high capital and result in high operating costs. Since designs must typically limit mass transfer contact to avoid CO2 equilibrium, operating envelopes are more constrained. Furthermore, selective re-absorption often has the advantage of rejecting some, though seldom all, undesirable organics, but the disadvantage of also rejecting weakly acidic or neutral sulfur compounds such as mercaptans, carbonyl sulfide (COS) and carbon disulfide (CS2), thus resulting in increased SOx emissions to the environment. Other potential means of minimizing acid gas contamination with aromatics in particular include fuel gas stripping of the rich solvent, condensation from the acid gas via refrigeration and adsorption from the acid gas using a regenerable molecular sieve, silica gel, or activated carbon bed, invariably at substantial expense.